One of the most challenging problems in the petroleum industry is the understanding and prediction of subsidence at the surface due to formation compaction that happens as a result of fluid withdrawal from the reservoir. In some oil fields (e.g., poorly compacted reservoirs), stress changes associated with reservoir compaction can have beneficial results on fluid recovery (e.g., oil and gas production).
However, reservoir compaction may also reduce permeability, causing surface subsidence and damaging well equipment. Subsidence phenomena can cause excessive stress at the well casing, which can result in casing buckling and/or casing sheer. Subsidence phenomena can also cause excessive stress within the completion zone, where collapse of structural integrity could lead to loss of production (e.g., due to pressure decline). Subsurface subsidence can result in problems at the wellhead or with pipeline systems and platform foundations. Mudline subsidence can cause fault activation or movement, which in turn can result in reduced wellbore stability (e.g., due to concrete cracking) or subsea wellhead failures. Open or closed fractures can occur in a production well or an injection well, or along a production length or an injection length.
Progressive activation of faults and fractures affect phenomena such as stress arching and a nonlinear stress path. Unlike standard compaction drive simulation, there is no simple linear method to account for the effects of stress on permeability, especially for fractured systems, in which the changes of permeability might be directional, localized, and strongly nonlinear. As a result, fluid flow in a porous medium under such scenarios cannot be simplified to compressibility or pressure dependent porosity/permeability changes. Modeling of such processes is achieved by incorporation of geomechanical effects resulting from fluid flow in the porous medium.
Thus, many applications in the petroleum industry require modeling of both the porous flow of reservoir fluids (reservoir simulation) and of mechanical deformation caused by reservoir stresses and displacements (geomechanical simulation) to produce realistic results of reservoirs under production and especially to simulate the behavior of naturally fractured reservoirs. For example, reservoir simulation coupled with geomechanical simulation is used to model reservoir fluid flows and physical phenomena such as compaction, subsidence, induced fracturing, enhancement of natural fractures and/or fault activation.
This coupling may be implemented using an algorithm in which information is exchanged between a reservoir simulator and a geomechanical simulator in an iterative, staggered manner. The coupling of geomechanical and reservoir simulations in hydrocarbon or gas reservoir production induces variations in time and space of reservoir pressure, saturation and temperature. In turn, changes in thermal and hydraulic reservoir properties may cause a modification of the stress state in and around the reservoir. The stress changes may then alter the reservoir fluid flow parameters and then the reservoir production scenario.
In conventional approaches, a reservoir model is selected, and then that reservoir model is utilized for the coupling (e.g., the model is utilized by both a reservoir simulator and a geomechanical simulator). Once a reservoir model is selected, then the coupling (e.g., both reservoir simulation and geomechanical simulation) must be fully implemented using only that model. Once coupling is completed using the selected model, if the coupling using the selected model leads to unsatisfactory results, the selected model is abandoned and a new (e.g., more complex) model is selected instead. Coupling must then be fully re-implemented using the new model. For example, after coupling (e.g., both reservoir simulation and geomechanical simulation) is completed using a “single porosity” model, if the results are unsatisfactory, the “single porosity” model is replaced with a more complex “dual porosity” model and the entire coupling process (e.g., both reservoir simulation and geomechanical simulation) is repeated using the new “dual porosity” model.